This section is intended to introduce various aspects of the art, which may be associated with exemplary embodiments of the present disclosure. This discussion is believed to assist in providing a framework to facilitate a better understanding of particular aspects of the present disclosure. Accordingly, it should be understood that this section should be read in this light, and not necessarily as admissions of prior art.
1. Field of the Invention
The present invention relates to the field of fluid separation. More specifically, the present invention relates to the separation of carbon dioxide and other acid gases from a hydrocarbon fluid stream.
2. Discussion of Technology
The production of hydrocarbons from a reservoir oftentimes carries with it the incidental production of non-hydrocarbon gases. Such gases include contaminants such as hydrogen sulfide (H2S) and carbon dioxide (CO2). When H2S and CO2 are produced as part of a hydrocarbon gas stream (such as methane or ethane), the gas stream is sometimes referred to as “sour gas.”
Sour gas is usually treated to remove CO2, H2S, and other contaminants before it is sent downstream for further processing or sale. The separation process creates an issue as to the disposal of the separated contaminants. In some cases, the concentrated acid gas (consisting primarily of H2S and CO2) is sent to a sulfur recovery unit (“SRU”). The SRU converts the H2S into benign elemental sulfur. However, in some areas (such as the Caspian Sea region), additional elemental sulfur production is undesirable because there is a limited market. Consequently, millions of tons of sulfur have been stored in large, above-ground blocks in some areas of the world, most notably Canada and Kazakhstan.
While the sulfur is stored on land, the carbon dioxide gas is oftentimes vented to the atmosphere. However, the practice of venting CO2 is sometimes undesirable. One proposal to minimizing CO2 emissions is a process called acid gas injection (“AGI”). AGI means that unwanted sour gases are re-injected into a subterranean formation under pressure and sequestered for potential later use. Alternatively, the sour gases are used to create artificial reservoir pressure for enhanced oil recovery operations.
For AGI, it is necessary to have a gas processing facility that separates out the acid gas components from the hydrocarbon gases. However, for “highly sour” streams, that is, production streams containing greater than about 15% CO2 and H2S, it can be particularly challenging to design, construct, and operate a facility that can economically separate contaminants from the desired hydrocarbons. Many natural gas reservoirs contain relatively low percentages of hydrocarbons (less than 40%, for example) and high percentages of acid gases, principally carbon dioxide, but also hydrogen sulfide, carbonyl sulfide, carbon disulfide and various mercaptans. In these instances, cryogenic gas processing may be beneficially employed.
Cryogenic gas processing is a distillation process sometimes used for gas separation. Cryogenic gas separation generates a cooled and liquefied gas stream at moderate pressures (e.g., 350-600 pounds per square inch gauge (psig)). In the case of cryogenic distillation of sour gas, liquefied acid gas is generated as a “bottoms” product. Since liquefied acid gas has a relatively high density, hydrostatic head can be beneficially used in an AGI well to assist in the injection process. This means that the energy required to pump the liquefied acid gas into the formation is lower than the energy required to compress low-pressure acid gases to reservoir pressure. Thus, cryogenic gas processing is particularly suitable for AGI.
Challenges also exist with respect to cryogenic distillation of sour gases. When CO2 is present at concentrations greater than about 5 mol. percent in the gas to be processed, it will freeze out as a solid in a standard cryogenic distillation unit. The formation of CO2 as a solid disrupts the cryogenic distillation process. To circumvent this problem, the assignee has previously designed various “Controlled Freeze Zone™” (CFZ™) processes. The CFZ™ process takes advantage of the propensity of carbon dioxide to form solid particles by allowing frozen CO2 particles to form within an open portion of the distillation tower, and then capturing the particles on a melt tray. As a result, a clean methane stream (along with any nitrogen or helium present in the raw gas) is generated at the top of the tower, while a liquid CO2/H2S stream is generated at the bottom of the tower.
Certain aspects of the CFZ™ process and associated equipment are described in U.S. Pat. Nos. 4,533,372; 4,923,493; 5,062,270; 5,120,338; and 6,053,007.
As generally described in the above U.S. patents, the distillation tower, or column, used for cryogenic gas processing includes a lower distillation zone and an intermediate controlled freezing zone. Preferably, an upper rectification zone is also included. The column operates to create solid CO2 particles by providing a portion of the column having a temperature range below the freezing point of carbon dioxide, but above the boiling temperature of methane at that pressure. More preferably, the controlled freezing zone is operated at a temperature and pressure that permits methane and other light hydrocarbon gases to vaporize, while causing CO2 to form frozen (solid) particles.
As the gas feed stream moves up the column, frozen CO2 particles break out of the feed stream and gravitationally descend from the controlled freezing zone onto a melt tray. There, the particles liquefy. A carbon dioxide-rich liquid stream then flows from the melt tray down to the lower distillation zone at the bottom of the column. The lower distillation zone is maintained at a temperature and pressure at which substantially no carbon dioxide solids are formed, but dissolved methane boils out. In one aspect, a bottom acid gas stream is created at 30° to 40° F.
The controlled freeze zone includes a cold liquid spray. This is a methane-enriched liquid stream known as “reflux.” As the vapor stream of light hydrocarbon gases and entrained sour gases moves upward through the column, the vapor stream encounters the liquid spray. The cold liquid spray aids in breaking out solid CO2 particles while permitting methane gas to evaporate and flow upward in the column.
In the upper rectification zone, the methane (or overhead gas) is captured and piped away for sale or made available for fuel. In one aspect, the overhead methane stream is released at about −130° F. The overhead gas may be partially liquefied by additional cooling, and the liquid returned to the column as “reflux.” The reflux liquid is injected as the cold spray into the spray section of the controlled freezing zone.
The methane produced in the upper distillation zone meets most specifications for pipeline delivery. For example, the methane can meet a pipeline CO2 specification of less than 2 mol. percent, as well as a 4 ppm H2S specification, if sufficient reflux is generated. However, more stringent CO2 specifications for natural gas exist for applications such as helium recovery, cryogenic natural gas liquids recovery, conversion to liquid natural gas (LNG), and nitrogen rejection.
The more stringent CO2 specifications may be met by increasing the quantity of liquid methane reflux. This, in turn, requires more and/or larger refrigeration equipment. In this respect, the process of generating cold liquid methane for the spray section requires equipment ancillary to the CFZ tower. This equipment includes pipes, nozzles, compressors, separators, pumps, and expansion valves. The more vigorously the operator wishes to remove CO2, the greater the refrigeration requirements become.
There is a need to reduce the refrigeration requirements of the CFZ process while still reducing the CO2 content down to very low levels. There is also a need for a cryogenic gas separation system and accompanying processes that are augmented by other CO2 removal techniques. Further, there is a need for a cryogenic gas separation process that is able to reduce the CO2 and H2S content of the gas down to levels acceptable for downstream liquefaction processes without increasing refrigeration equipment capacity.